In oilfield operations, drilling mud is often used while drilling a well to reach a subterranean formation. Drilling mud may also be used to treat the formation to enhance or restore the productivity of the well. The drilling mud is pumped into a drill string to which a drill bit is attached. The drilling mud typically exits the drill string through openings in the drill bit to lubricate the bit and to carry cuttings up an annulus between the drill string and the wellbore for disposal at the surface. Drilling mud, when used as a stimulation treatment, may fall into two main groups, hydraulic fracturing treatments and matrix treatments. Fracturing treatments are performed above the fracture pressure of the formation and create a highly conductive flow path between the reservoir and the wellbore. Matrix treatments are performed below the formation fracture pressure and generally are designed to restore the natural permeability of the formation following damage to the near-wellbore area.
A commonly used method to treat the matrix is “matrix acidizing”, which is generally understood in the industry to mean the treatment of the formation with a stimulation fluid containing a reactive acid. In sandstone formations, the acid reacts with the soluble substances in the formation matrix to enlarge the pore spaces. In carbonate formations, the acid dissolves the entire formation matrix. In each case, the matrix acidizing treatment improves the formation permeability to enable enhanced production of formation fluids. Matrix acidizing operations are ideally performed at high rate, but at treatment pressures below the fracture pressure of the formation. This enables the acid to penetrate the formation and extend the depth of treatment while avoiding damage to the formation.
An emulsion of substances may be used as the drilling mud (e.g., oil-based mud or water-based mud) during matrix acidizing. The emulsion is defined by a non-aqueous external phase and an aqueous internal phase. In this drilling mud a non-aqueous “oleaginous” external phase (e.g. oil or synthetic polymers) may be used to inhibit swelling of water-sensitive drill cuttings (e.g. shale). The internal aqueous phase may be one or more acids. For example, typically the reactive acid comprises hydrochloric acid (HCl) and a blend of acid additives. It is also common for acid treatments to include a range of acid types or blends, such as acetic, formic, hydrochloric, hydrofluoric, and fluroboric acids. In addition to the non-aqueous external phase and the aqueous internal phase, compositions of drilling fluids often contain at least trace amounts of chemical emulsifying agents which act to form the non-aqueous external phase emulsions.
Depending on the characteristics of the formation and the treatment fluid, it may be helpful to first emulsify the acid before pumping it down the wellbore. The preparation of acid emulsion is traditionally performed off-site, i.e. at a location that is away from the wellsite, and is generally based on a batch mixing method. Creating the emulsion may be performed by using a tank to recirculate an acid mixture until a complete homogeneous state is achieved. The emulsifying agent is transferred into a batch tank and a pump may be used to recirculate the batch tank until the desired emulsion is created. Once the emulsion is created, the contents of the batch tank can be delivered to the wellsite as a finished product. On-site emulsification may also be performed using a plurality of fluid tanks and a circulation loop, with or without a buffer tank and a pump. The aqueous phase and the non-aqueous phase may be transferred to the circulation loop and therein circulated to mix the aqueous and non-aqueous phases to produce the emulsion. Additives may also be added through fluid tanks or in the circulation loop to enhance emulsification.
Well mixed emulsions penetrate deeper into the formation around the wellbore before the aqueous phase, the acid, begins to react with the formation or the fluid within the formation thereby better enabling recovery of a desired product from the formation and increasing permeability. When emulsions are mixed incorrectly, provided in incorrect ratios, subject to contamination fluids, or subject to certain shear energies, the emulsions may invert. Inversion occurs when the aqueous internal phase becomes continuous and no longer coated by the non-aqueous external phase. When inversion occurs, the acid-in-oil emulsions will have a shorter range of penetration into the wellbore formation, thereby hindering recovery of fluids from the formation.
Currently, when emulsions are pumped into the wellbore, there are no means to detect inversion in real time, and therefore recovery of emulsion quality is hindered by the inability to detect inversion.